1. Field of the Invention
A selected geophysical analogue of a petrophysical parameter is measured over the lifetime of a mineral deposit. Quantitative time-dependent changes in the selected geophysical analogue are indicative of changes in the re-distribution of the mineral within the deposit by reason of mineral production management.
2. Discussion of Related Art
Geophysical surveys are used to discover the extent of subsurface mineral deposits such as oil, natural gas, water, sulphur, etc. Geophysical methods may also be used to monitor changes in the deposit, such as depletion resulting from production of the mineral over the natural lifetime of the deposit which may be many years. The usefulness of a geophysical study depends on the ability to quantitatively measure and evaluate some geophysical analogue of a petrophysical parameter that is directly related to the presence of the mineral under consideration.
Potential-field measurements such as electrical resistivity of the rocks penetrated by a borehole may be indicative of the rock conductivity. Radioactive and gravity fields may be of interest.
Seismic methods may be applied to production-management monitoring. As is well known to geophysicists, a sound source at or near the surface of the earth is caused periodically to inject an acoustic wavefield into the earth at each of a plurality of regularly-spaced survey stations. The wavefield radiates in all directions to insonify the subsurface earth formations whence it is reflected back to be received by seismic sensors (receivers) located at designated stations also located at or near the surface of the earth. The seismic sensors convert the mechanical earth motions, due to the reflected wavefield, to electrical signals. The resulting electrical signals are transmitted over a signal-transmission link of any desired type, to instrumentation, usually digital, where the seismic data signals are archivally stored for later processing.
The travel-time lapse between the emission of a wavefield by a source and the reception of the resulting sequence of reflected wavefields by a receiver, is a measure of the depths of the respective earth formations from which the wavefield was reflected. The relative amplitudes of the reflected wavefields may be a function (an analogue) of the density and fluid content of the respective earth formations from which the wavefields were reflected. The frequency content of the returned signals may be influenced by the type of fluid content of the sought-for mineral.
In a commonly-used 3-D seismic survey, the seismic observation stations are preferably distributed in a regular grid over an area of interest with inter-station spacings on the order of 25 meters. The processed seismic data associated with a single receiver are customarily presented as a one-dimensional time scale recording displaying rock layer reflection amplitudes as a function of two-way wavefield travel time. A plurality of seismic traces from a plurality of receivers sequentially distributed along a line of survey may be formatted side-by-side to form an analog model of a cross section of the earth in the form of two-dimensional imaging. Seismic sections from a plurality of intersecting lines of survey distributed over an area of interest, provide three-dimensional imaging.
In the case of an oil field, by way of example but not by way of limitation, a series of 3-D surveys over the area embraced by the oil field could be surveyed at regular time intervals such as every day or every six months during the lifetime of the oil deposit. Thus, one could monitor the depletion rate of the fluid content of the field. That sort of study would comprise a 4-D, time-lapse study of the metamorphosis of the mineral deposit over time.
Wavefield reflection from a subsurface interface depends on the acoustic characteristics of the rock layers that define that interface such as density and wavefield propagation velocity. In turn those characteristics depend inter alia on the rock type, rock permeability and porosity, fluid content and fluid composition. In a subsurface reservoir, the fluid phase-change from gas to oil or oil to water, may act as a weak reflecting surface to generate the so-called bright spots sometimes seen on seismic cross sections. It is reasonable to expect that a change in the level or the characteristics of the reservoir fluids will create a change in the seismic signature associated with the reservoir. The amplitude level of the seismic signature of a reflection associated with a fluid interface is an analogue of a petrophysical attribute, namely the fluid content of the rock layer. Thus, time-lapse or 4-D tomography, that is, the act of monitoring the regional seismic signature of a reservoir over a long period of time would allow monitoring the depletion of the reservoir or the mapping advance of thermal front in a steam-flooding operation.
The term "signature" used herein means the variations in amplitude and phase of an acoustic wavelet (for example, a Ricker wavelet) expressed in the time domain as displayed on a time scale recording. The impulse response means the response of the instrumentation to a spike-like Dirac function.
Successful time-lapse monitoring requires that differences among the processed 3-D data sets must be attributable solely to physical changes in the petrophysical characteristics of the reservoir. That criterion is severe because changes in the data-acquisition equipment and changes in the processing algorithms, inevitable over many years, introduce differences among the separate surveys. Long-term environmental changes in field conditions such as weather and culture affect the outcome. If time-lapse tomography is to be useful for quantitative reservoir monitoring, instrumental and environmental influences that are not due to changes in reservoir characteristics must be transparent to the before-and-after seismic data sets. Successful time-lapse tomography requires careful preliminary planning.
One way to avoid selected time-dependent environmental changes and updated state-of-the-art instrumental changes is to permanently emplace seismic detectors in one or more boreholes in and around the mineral deposit and to use identical processing methods throughout the monitoring period.
U.S. Pat. No. 5,461,594 issued Oct. 24, 1995 to Denis Mougenot et al. for a METHOD OF ACQUIRING AND PROCESSING SEISMIC DATA RECORDED ON RECEIVERS DISPOSED VERTICALLY IN THE EARTH TO MONITOR THE DISPLACEMENT OF FLUIDS IN A RESERVOIR, according to the Abstract, teaches a method of acquiring and processing seismic data for the repetitive monitoring of displacement of fluids impregnating a reservoir deep in the subsurface below the surface weathering zone comprises the steps of making at each point on a predetermined grid on the surface a vertical axis shallow borehole in the earth above the reservoir passing through the weathered layer, positioning in each borehole along its vertical axis a plurality of fixed receivers adapted to be connected separately to the seismic recorder on the surface, emitting near each borehole seismic waves into the earth by means of an emitter on the surface or close by the surface near the vertical axis of the borehole, recording for each borehole by means of receivers placed in the borehole to receive direct incident seismic waves and the seismic waves reflected at the interfaces of the deep strata of the subsurface, each receiver providing a separate record of an incident wave and a plurality of reflected waves, and carrying out the following process steps for each borehole: picking the first break of direct incident waves, horizontalizing the reflected waves, separating the reflected waves and the direct incident waves, deconvolving receiver by receiver the reflected waves by the direct incident wave in order to obtain a zero-phase trace for each receiver and stacking the zero-phase traces from the receivers to obtain a low coverage/zero-offset, zero-phase trace. This patent was concerned with a land system but its teachings could be extended to a marine system by installing the sensors in boreholes or crypts on the sea floor.
The inventors of the '594 patent recognize the need for maintaining identical instrumentation and processing methods throughout the reservoir-monitoring epoch. Therefore, sensors are permanently sealed in a plurality of boreholes distributed over the area of interest. A standard source and standard processing methods are used to maintain constant data-gathering/interpretation conditions throughout the monitoring epoch. But to monitor properly a reservoir of large areal extent, many hundreds or thousands of densely-distributed borehole-emplaced sensors would be needed, a very uneconomical installation indeed, which renders that method to not be very practical. Furthermore, use of surface sources necessarily invokes the unwanted filtering effects of near-surface earth layers as well as changing environmental effects over time.
D. L. Howlett, in U.S. Pat. No. 5,042,611 for a METHOD AND APPARATUS FOR CROSS-WELL SEISMIC SURVEYING teaches a method for,inter-well seismic logging that includes a seismic source that is lowered into a source borehole and a plurality of seismic receivers lowered into at least another borehole. Signals generated from the seismic source pass through the earth and are received by the respective receivers after transmission through a geological anomaly of interest. The seismic data are recorded and processed to form a profile that represents the geological configuration between the wells. Instrumentation emplaced in several boreholes in various combinations are suggested so that the geological anomaly may be examined along several different wavefield trajectories.
Although Howlett teaches cross-well tomography, he does not suggest that technique for use with permanently-emplaced instrumentation in a borehole over the long term in the context of 4-D tomography.
In a paper published in Geophysics, v. 62, n. 2 (March-April 1997) pp. 495-504 entitled FRACTURE DETECTION USING CROSSWELL AND SINGLE WELL SURVEYS, E. L. Majer et al. employ cross-well seismic data for time-lapse imaging of a gas filled vertical fracture zone in the Riley limestone in an Oklahoma borehole test facility.
A United Kingdom patent application GB2302113A, entitled Production Wells Having Permanent Downhole Formation Evaluation Sensors, filed in the name of P. Tubel et al. discloses a permanent downhole sensor installation. Here, sensors are permanently emplaced downhole, in combination with the production string, in oil, gas or injection wells for collecting real time data. The data are used for, among other purposes, (a) defining the reservoir, (b) defining the distribution of oil, water or gas in a reservoir with respect to time and (c) monitoring the saturation, depletion and movement of oil, water and gas in real time. The teachings of this reference are confined to studies of the environs immediately surrounding the well in which the instrumentation is installed. Information regarding fluid distribution between wells, in a multi-well oil patch, is not contemplated.
There is a need for a method for monitoring the time-varying changes of one or more selected petrophysical attributes that result from the time-lapse metamorphosis of a mineral deposit due to long-term resource management and mineral production therefrom.